Method and apparatus for connecting well heads of steam stimulated hydrocarbon wells

ABSTRACT

A system for a steam-stimulated hydrocarbon well pad includes an injection piping assembly at an injection well head and a production piping assembly at a production well head. The injection piping assembly comprises first and second steam conduits for connecting respective ports of an injection well head a steam injection pipeline. The steam conduits are mounted to a frame for transportation as a unit. The production piping comprises a production conduit for connecting a first fluid port of the production well head to a hydrocarbon production pipeline and a gas conduit in fluid communication with the wellbore through a second fluid port of the production well head. The production conduit and the gas conduit mounted to a frame for transportation as a unit.

FIELD

This relates to onshore hydrocarbon wells, in particular, to piping assemblies for connecting wellheads to trunk lines.

BACKGROUND

Many oil production facilities have a plurality of wells generally in proximity to one another on a well pad. Such wells may be positioned for stimulation of and production from different pans of a reservoir. A set of wells may be arranged on a common well pad. The wells may include injection wells for pumping fluids into the reservoir, and production wells for extracting hydrocarbons from the reservoir.

Fluids such as steam or solvents may be provided from a supply pipeline for injection into injection wells, and extracted fluids such as oil or emulsions containing oil, tars, bitumen or natural gas may be extracted from the wells to production pipelines for transportation.

Typically, supply pipelines and production pipelines are connected to a plurality of control devices, such as valves which are housed in enclosures at the well pad. Piping connections are installed between the control enclosures and the wellheads. The piping connections are typically custom fabricated and installed at the facility to provide proper fitment. Such custom fabrication and installation is time consuming and expensive especially in remote sites.

SUMMARY

An example piping assembly for a well head of a steam-stimulated hydrocarbon well comprises: a first fluid conduit for connecting a first fluid port of the well head to a first pipeline; a second fluid conduit for connecting a second fluid port of the well head to a second pipeline; the first fluid conduit and the second fluid conduit mounted to a frame for transportation of the fluid conduits and the frame as a unit.

An example method of completing a steam-stimulated hydrocarbon well comprises: moving a structural frame to a well head of the well, the frame carrying first and second fluid conduits for connecting the well head its first and second pipelines, respectively; attaching the first fluid conduit to a first port of the well head and attaching the second fluid conduit to a second port of the well head; connecting the first fluid conduit with the first pipeline, thereby establishing fluid communication between the first port and the first pipeline; and connecting the second fluid conduit with the second pipeline, thereby establishing fluid communication between the second port and the second pipeline.

A system for a steam-stimulated hydrocarbon well pad, comprises: a plurality of trunk pipelines, comprising a steam injection pipeline, a hydrocarbon production pipeline and a blanket gas pipeline; an injection piping assembly at an injection well head, the injection piping assembly comprising: a first steam conduit tor connecting a first fluid port of the injection well head to the steam injection pipeline; a second steam conduit for connecting a second fluid port of the injection well head to the steam injection pipeline; the first and second steam conduits mounted to a frame for transportation as a unit; a production piping assembly at a production wellhead, the production piping assembly comprising: a production conduit for connecting a first fluid port of the production well head to the hydrocarbon production pipeline; a gas conduit in fluid communication with the production well bore through a second port of the production wellhead; the production conduit and the gas conduit mounted to a frame for transportation as a unit.

BRIEF DESCRIPTION OF DRAWINGS

In the drawings, which depict example embodiments:

FIG. 1 is a schematic view of a subterranean reservoir;

FIG. 2 is a schematic top elevation view of a steam-assisted gravity drainage (SAGD) facility at a reservoir;

FIG. 3 is a perspective view of a wellpad of a SAGD facility;

FIG. 4 is an isometric view of an injection assembly;

FIGS. 5A-5B are schematic views of swivel links of the injection assembly of FIG. 4;

FIG. 5C is a schematic view of an expansion loop of the injection assembly of FIG. 4.

FIG. 6 is an isometric view of a production assembly;

FIGS. 7a-7b are a schematic flow diagram of the injection assembly of FIG. 4;

FIGS. 8a-8b are a schematic flow diagram of the production assembly of FIG. 6;

FIGS. 9a-9b are a schematic diagram of a well pad in a startup configuration;

FIG. 10 is an isometric view of the injection assembly of FIG. 4 in a startup configuration;

FIG. 11 is an isometric view of the production assembly of FIG. 6 in a startup configuration;

FIG. 12 is an isometric view of the injection assembly and production assembly of FIGS. 10-11, with trunk pipe lines;

FIGS. 13a-13b are a schematic flow diagram of the injection assembly of FIG. 10 in a startup configuration;

FIGS. 14a-14b are a schematic flow diagram of the production assembly of FIG. 11 in a startup configuration;

FIG. 15 is a perspective view of the injection assembly of FIG. 10 being installed to a well head;

FIG. 16 is a flow chart

FIG. 17 is a perspective view of a slant well injection assembly: and

FIG. 18 is a perspective view of a slant well production assembly.

FIGS. 19A-19C are schematic overhead views of example well pad configurations.

DETAILED DESCRIPTION

FIG. 1 depicts a schematic view of a subterranean reservoir 100, and a wellpad 102 formed on the surface above reservoir 100. Wellpad 102 has a plurality of well pairs. Well pairs comprise an injection well 104 and a production well 106.

As depicted reservoir 100 is a geological formation suitable for hydrocarbon or bitumen production by processes such as SAGD (steam-assisted gravity drainage). In a SAGD process, steam is injected into a reservoir at high temperature and pressure through an injection well 104. The steam heats and lowers the viscosity of hydrocarbons in reservoir 100, causing the hydrocarbons to drain under the influence of gravity to a production well 104. Pumping devices at the surface or at the foot of the production well draw hydrocarbons into the well bore and forces the hydrocarbons to the surface.

FIG. 2 depicts an overhead schematic view of a SAGD production facility 110 for extracting hydrocarbons (e.g. bitumen) from reservoir 100. The production facility 110 has a plurality of well pads 102, each with one or more pairs of an injection well 104 and a production well 106, connected to a trunk 107 with a plurality of trunk pipelines. As depicted, the facility 110 has six well pads 102, however production facilities may have any number of multiple well pads or may have a single well pad. Each well 104, 106 is connected with a steam supply trunk line 112, a production trunk line 114, and a blanket gas supply line 116. Steam and a hydrocarbon blanket gas (e.g. natural gas) may be supplied through supply lines 112, 116 from a central production installation.

Trunk lines 112, 114, 116 may be routed through a weather resistant enclosure 120. Controls (valves, etc.) may be provided within enclosure 120 for regulating flow to and from each well 104, 106.

Each well 104, 106 is connected with one or more of trunk lines 112, 114, 116 by way of a piping assembly 122. Each piping assembly 122 may be custom-fabricated at or near production facility 110 based on the design, dimensions, and configuration of well pad 102, which may be time-consuming and expensive.

FIG. 3 depicts an overhead perspective view of another well pad 202. Like well pad 102, well pad 102 has a plurality of injection wells 104 and production wells 106. Each well 104, 106 is connected with one or more of trunk lines 112, 114, 116 by a assembly. Injection wells 104 are connected by an injection assembly 204 as depicted in FIG. 4 and production wells are connected by a production assembly 206 as depicted in FIG. 6.

As depicted, assemblies 204, 206 are of modular construction, with piping mounted to a frame 208. Frame 208 may be placed atop pilings 209 on well pad 102. FIG. 4 shows an example injection assembly 204 in greater detail. Injection assembly 204 includes at least one steam injection conduit 210 for receiving pressurized steam from trunk line 112 and injecting it down the bore of the injection well 104. As depicted, the injection assembly 204 includes two steam injection conduits 210-1, 210-2. Injection conduit 210-1 is a long line for injection of steam near the toe (bottom) end of the well bore, and injection conduit 210-2 is a short line for injection of steam at an intermediate location along the well bore. In some embodiments, assembly 204 may include additional steam conduits, which may deliver steam at different depths along the well bore.

As depicted, the long string steam conduit 210-1 and the short string steam conduit 210-2 are fed through respective inlets 216-1, 216-2 (individually and collectively, inlets 216) in communication with steam supply trunk line 112. As depicted, each inlet 216 is a flanged connection. Alternatively, long string steam conduit 210-1 and short string steam conduct 210-2 may merge and communicate with trunk line 112 through a single inlet.

Each of steam conduits 210-1, 210-2 has a releasable coupling, e.g. a bolted flange, for connection to a port of well head 104, and a releasable coupling, e.g. a bolted flange, for connection to steam supply trunk line 112.

Steam conduits 210-1, 210-2 have respective flow control valves 220-1, 220-2 operable to selectively admit or block flow of steam to well head 104. Steam conduits 210-1, 210-2 also have flow, pressure and temperature monitoring devices, such as flow meters, pressure transducers 224-1, 224-2 and thermocouples (not shown). The monitoring devices provide outputs such as electrical signals indicative of the flow rate, pressure and temperature of steam in the respective fluid conduit 210-1, 210-2. Flow control valves 220-1, 220-2 are operated by an automatic control system which receives signals from the monitoring devices and receives input (e.g. from an operator) of a requested flow rate, pressure or temperature of steam. The control system may be configured to block or restrict flow of steam in the event of an excessive temperature, pressure or flow reading.

Steam conduits 210-1. 210-2 have respective articulated links 226-1 226-2. Each articulated swivel link comprises piping segments pivotally joined to one another at joints 228. As shown in FIGS. 5A-5B, joints 228 of articulated links 226 compensate for movement caused by thermal expansion while maintaining the fluid seal of the connection. For example, during operation, the temperature of wellhead 104 or fluid conduits 210 increases, which may cause well head 104 to expand vertically as indicated by the arrow in FIG 5A and may cause fluid conduit 210 to expand along its length. Joints 228 may permit pipe segments to pivot relative to one another to compensate for such expansion. For example, as shown in FIG. 5A, fluid conduit 210 couples to well head 104 at fluid port 230. As well head 104 expands, fluid pod 230 moves vertically upwards. Segments of fluid conduit 210 pivot relative to one another as shown by arrows R1 to compensate for movement of fluid port 230.

One or more of joints 228 may permit rotation about multiple axes. For example, as shown in FIG 5B, joint 228-2 permits rotation as indicated by arrow R2 around a generally vertical axis. Such rotation may compensate for misalignment between well head 104 and fluid conduit 210. Such misalignment may result, for example, from manufacturing or installation variances or defects, thermal expansion, or the like.

Referring again to FIG 4, each steam conduit 210 may have one or more expansion loops 230. Expansion loops 230 are pipe segments joined in a U-shaped configuration. As shown in FIG. 5C, expansion loops 230 are configured to deflect slightly to compensate for dimensional changes or misalignment, e.g. due to thermal expansion. For example, as depicted in FIG. 5C, expansion loop 230 may deflect to the position shown in broken lines.

Injection assembly 204 further includes at least one blanket gas conduit 232 for receiving blanket gas from blanket gas supply line 116.

Blanket gas conduit 232 delivers pressurized blanket gas down the injector well bore. The blanket gas is delivered to a casing surrounding the steam injection tubing, and insulates the steam-carrying wellbore to prevent or limit loss of heat from the injected steam to the surrounding formation. In some examples, the blanket gas may be fuel gas, nitrogen, methane, a mixture thereof, or other suitable gases that will be apparent to skilled persons. Blanket gas conduit 232 may have a releasable coupling, e.g. a bolted flange, at an input end for connection to trunk line 116 to receive blanket gas and a releasable coupling, e.g. a bolted flange at an output end for connection to well head 104 to deliver blanket gas.

Blanket gas conduit 232 may be connected with well bead 104 in through a bubble panel 227, which is configured to regulate pressure in bubble line 250 and produce an output (e.g. an electrical signal) indicative of the pressure at which gas begins to flow down the well bore. As will be apparent, this pressure is indicative of the pressure in the well bore at the bubble line outlet.

Each of steam conduits 210-1, 210-2 and blanket gas conduit 232 is mounted to structural members 218 of frame 208. Steam conduits 210 and blanket gas conduit 232 may be mounted, for example, using welds, bolts, or other suitable fastening devices or techniques. Structural members may be metal (e.g. steel) bars or tubes, and may be welded or fastened together to form the frame 208.

As shown in FIG. 4, injection assembly 204 may define a rectangular spatial envelope E which circumscribes the injection assembly 204. That is spatial envelope E is the smallest three-dimensional rectangular shape such that no portion or component of injection assembly extends outside of spatial envelope E.

In some embodiments, injection assembly 204 may fit within a spatial envelope E that is within a standard intermodal shipping container, e.g. no greater than 39 feet 4 inches in length, 7 feet 6 inches in width and 7 feet 5 inches in height. In some embodiments, injection assembly 204 may be sized so that two assemblies fit in such a container. That is, envelope E may be no greater than 19 feet 8 inches in length, 7 feet 6 inches in width and 7 feet 5 inches in height. Conveniently, such sizing may permit assemblies to be fabricated and assembles remotely (e.g. overseas) from the location of reservoir 100, and easily and efficiently shipped to reservoir 100. This may allow for cost reduction relative to conventional systems which typically require large custom-fabricated components which are difficult to ship and therefore typically need to be fabricated close to reservoir 100.

FIG. 8 depicts an isometric view of production assembly 206 installed at production well bead 106. As depicted, production assembly 206 includes at least one emulsion conduit 234 for transporting produced fluids from production well head 106 to production trunk line 114. The produced fluid may be a mixture of mobilized bitumen, water and entrained solids. Emulsion conduit 234 is connected a respective port of well head 106 and to trunk line 114, to receive produced fluids from well head 106 and deliver the produced fluids to trunk fine 114. Connections with well head 106 and trunk line 114 may, for example, be releasable couplings such as bolted flanges.

Emulsion conduit 234 has a flow control valve 236, operable to selectively permit or block flow from well head 106 toward production trunk line 114. Emulsion conduit 234 also has temperature and pressure monitoring devices such as a pressure transducer 238 and a thermocouple (not shown) for producing outputs (e.g. electrical signals) indicative of the temperature and pressure of the produced fluid. Flow control valve 236 may be operated manually or by an automated control system configured to receive signals from the flow meter and pressure and temperature monitoring devices and open and close the flow control valve 236 based on those signals. The flow control valve 336 may be actuated to block or restrict flow if an excessive temperature, pressure or flow rate is detected.

Production assembly 206 also has an annulus gas conduit 242. Annulus gas conduit 242 communicates with trunk line 117 and with a port on well head 106 connected to an annular passage within the well bore, e.g. by releasable couplings such as bolted flanges. The annular passage permits fluid communication between a mechanical lift device (e.g. a pump) in the wellbore and gas at the surface. Annulus gas pressure is lower than reservoir pressure in order to draw fluid to the mechanical lift device and ensure that the mechanical lift device is submerged in fluid, but high enough to limit water flashing in the produced emulsion. Non-condensable liquids, light end hydrocarbons and water vapour travel up the well bore and through annulus gas conduit 242 to trunk line 117 and to a processing facility. Hydrocarbons in the gas may then be used as fuel gas for steam generation.

Annulus gas conduit 242 has a pressure control valve 244, operable to selectively permit or block flow of annulus gas between well head 106 and trunk line 117. Annulus gas conduit 242 also has a pressure transducer and a temperature monitoring device (not shown). Pressure control valve 244 may be operated manually or by an automated control system configured to receive signals from the pressure meter and pressure and temperature monitoring devices and open and close the pressure control valve 242 based on those signals.

Emulsion conduit 234 and annulus gas conduit 242 have respective articulated links 239, 248 substantially similar to articulated links 225 of injection assembly 204. The articulated links include movable joints 230 which allow pivoting of pipe segments relative to one another to compensate for movement or misalignment, such as movement or misalignment due to thermal expansion. At least one of joints 230 may permit pivoting a about more than one axis, such that articulated links 239, 248 can compensate for both vertical and horizontal movement or misalignment as depicted in FIGS. 5A-5B.

Emulsion conduit 234 and annulus gas conduit 242 also have respective expansion loops 230-3, 230-4, substantially similar to expansion loops 230-1, 230-2 of injection assembly 104. Expansion loops 230-3, 230-4 are configured, to deflect under and compensate for movement or thermal expansion, as shown in FIG. 5C.

Production assembly 206 also has a bubble line 250. Bubble line 250 connects in fluid communication with well head 106 and with trunk line 116 by releasable couplings, e.g. bolted flanges. Bubble line 250 is a small-gauge line for injecting gas (e.g. fuel gas or nitrogen) down the well bore under pressure. Bubble line 250 is connected with well head 206 through a bubble panel 227, which is configured to regulate pressure in bubble line 250 and produce an output (e.g. an electrical signal) indicative of the pressure at which gas begins to flow down the well bore. As will be apparent, this pressure is indicative of the pressure in the well bore at the bubble line outlet.

Each of emulsion conduit 234, annulus gas conduit 242 and bubble line 250 is mounted to structural members 218 of frame 208, for example, using, welds, holts or other suitable fasteners or techniques.

As shown in FIG. 6, production assembly 206 may define a rectangular spatial envelope E which circumscribes the injection assembly 206. That is spatial envelope E is the smallest three-dimensional rectangular shape such that no portion or component of injection assembly extends outside of spatial envelope E.

In some embodiments, production assembly 206 may fit within a spatial envelope E that is within a standard intermodal shipping container, e.g. no greater then 39 feet 4 inches in length, 7 feet 6 inches in width and 7 feet 5 inches in height. In some embodiments, injection assembly 204 may be sized so that two assemblies fit in such a container. That is, envelope E may be no greater than 19 feet 8 inches in length, 7 feet 6 inches in width and 7 feet 5 inches in height. For example, one injection assembly 204 and one production assembly 206 could be fit within a single 40 foot intermodal shipping container. Conveniently, such sizing may permit assemblies to be fabricated and assembles remotely (e.g. overseas) from the location of reservoir 100, and easily and efficiency shipped to reservoir 100. This may allow for cost reduction relative to conventional systems which typically require large custom-fabricated components which are difficult to ship and therefore typically need to be fabricated close to reservoir 100.

FIGS. 7a-7b are a schematic flow diagram depicting flow through injection assembly 204 during operation. Pressurized steam is received from trunk line 112 and flows through steam conduits 210-1, 210-2 to respective pods on well head 104 and down the well bore. Flow through the steam conduits 210-1, 210-2 is governed by valves 220-1, 220-2, which may be operated manually or automatically based on signals from flow meters 222-1, 222-2, pressure transducers 224-1, 224-2 and thermocouples 225-1, 225-2. Blanket gas is received from trunk line 116 and flows through blanket gas conduit 232 to a port on well head 104 and down the well bore. Blanket gas conduit 232 passes through bubbler panel 227, which regulates the pressure in blanket gas conduit 232 and outputs the pressure at which blanket gas begins to flow downhole.

FIGS. 8a-8b are a schematic flow diagram depicting flow through production assembly 206 during operation. A pumping device in the well bore forces fluids up the wellbore and through well head 106. As noted, the produced fluids may be an emulsion of liquid and gaseous hydrocarbons, water and entrained particulates. The produced fluid flows through emulsion conduit 234. Flow through the emulsion conduit is governed by valve 236, either manually or automatically based on signals from pressure transducer 238 and a thermocouple installed downhole in the reservoir.

Bubble line 250 receives pressurized gas and communicates with well head 106 and the well bore by way of bubbler panel 227. Instruments in the bubbler panel measure and regulate pressure in the bubble line 250 and produce an output indicative of the pressure at which gas begins to flow down the well bore, which is itself indicative of pressure in the well bore.

FIGS. 4-6, 7 a-b, 8 a-8 b depict injection assembly 204 and production assembly 206 during operation to produce hydrocarbons. In some embodiments, injection assemblies 204 and production assemblies 206 may also be configured and operated in a reservoir startup mode, during which steam is circulated through reservoir 100 to transfer heat to the reservoir.

FIGS. 9a-9b depict a schematic view of a well pad 102′ in startup configuration. In the startup configuration, additional crossover piping 302 is installed between each injection assembly 204 and the corresponding production assembly 206. Steam is carried from injection assembly 204 to production assembly 206 and is simultaneously injected down both the injection and production well bores through well beads 104, 106.

Steam is forced up the well bores and produced at both well heads 104, 106. Steam produced at injection well head 104 is carried to the production assembly 206 through crossover piping 302. Produced steam is carried from production assembly 206 to a startup skid 300 through steam trunk line 112.

FIG. 10 is an isometric view of injection assembly 206 in startup configuration. In such configuration, injection assembly 206 has additional crossover piping 302 including a crossover injection pipe 252 and a crossover production pipe 254.

Crossover injection pipe 252 connects with short string steam injection conduit 210-2 at a releasable coupling 256, e.g. a bolted flange. Coupling 256 is located upstream of flow control valve 220-2. Crossover injection pipe 252 extends from coupling 256 and joins a pipe (not shown) in communication with production assembly 206.

Crossover production pipe 254 connects with short string steam injection conduit 210-2 at a releasable coupling 258, e.g a bolted flange, located downstream of flow control valve 220-2. Crossover production pipe 254 likewise extends from flanged coupling 258 and communicates with production assembly 206.

FIG. 11 is an isometric view of production assembly 206 in startup configuration. In startup configuration, production assembly 206 has additional crossover piping 302 including an injection crossover pipe 260, a production crossover pipe 262 and a tie pipe 264. Injection crossover pipe 260 connects to annulus gas conduit 242 in fluid communication, at a location downstream of valve 244. Injection crossover pipe 260 may, for example, join annulus gas conduit 242 at a releasable coupling 261, such as a bolted flange. Injection crossover pipe 260 receives pressurized steam from crossover injection pipe 252 of injection assembly 204. In some embodiments, crossover injection pipe 252 may connect with annulus gas trunk line 117. In other embodiments, crossover injection pipe 252 may communicate with crossover injection pipe 260 by way of another pipe, which may be temporarily installed for crossover operation.

Production crossover pipe 262 connects in fluid communication with annulus gas conduit 242 at a location upstream of valve 244. Production crossover pipe 262 may, for example, join annulus gas conduit 242 at a releasable coupling 268 such as a bolted flange. Production crossover pipe 262 receives steam produced from the production well bore due to steam injection at wells 104 and 106.

Tie pipe 264 connects emulsion conduit 234 in fluid communication with annulus gas conduit 242 such that steam may be produced, from well head 106 into emulsion conduit 234 and flow into annulus gas conduit 242 through tie pipe 264. Tie pipe 264 may join emulsion conduit 234 and annulus gas conduit 242 at respective flanged couplings 270, 272.

Each of the crossover pipes mounted to structural members 218 of the respective frame 208, for example, using, welds, bolts or other suitable fasteners or techniques.

FIG. 12 is a perspective view of injection assembly 204 and production assembly 206 along with associated trunk, lines during startup. As depicted, each of steam conduits 210-1, 210-2, emulsion conduit 234 and annulus gas conduit 242 are connected to trunk lines as during normal operation. That is, steam conduits 210 are connected with steam trunk line 112, emulsion conduit 234 is connected with emulsion trunk line 114 and annulus gas conduit 242 is connected with annulus gas trunk line 117. Pressurized steam is delivered to both the injection and production wells from steam trunk line 112 and then produced from both wells and returned through annulus gas trunk line 117 to a startup skid 300 (FIGS. 9a-9b ), where it may be processed and recirculated.

Injection crossover pipe 252 of injection assembly 204 is connected in fluid communication with injection crossover pipe 260 of production assembly 206 through a first trunk crossover 274. Production crossover pipe 254 of injection assembly 204 is connected in fluid communication with production crossover pipe 262 of production assembly 206 through a second trunk crossover 276. Such connections may be achieved by releasable couplings, e.g. bolted flanges.

FIGS. 13a -13 b, 14 a-14 b depict schematic flow diagrams of flow in injection assembly 204 and production assembly 206 in startup configuration. As shown in FIGS. 13a-13b , steam is delivered to each of steam conduits 210-1, 210-2 from steam trunk line 112. Steam is injected into the injection well through long string steam conduit 210-1 and well head 104. Valve 220-2 of short string steam conduit 210-2 is closed and steam in short string steam conduit 210-2 is redirected to the production assembly 206 through injection crossover pipe 252.

Injection of steam into the injection well causes circulation of steam in the injection well and ultimately forces steam up the well bore, where it is produced through well head 104 into short string steam conduit 210-2. Since valve 220-2 is closed, produced steam flows-through production crossover pipe 254 to production assembly 206.

Referring to FIGS. 14a-14b , injection crossover pipe 260 receives steam from the injection assembly 204 through trunk crossover 274. Steam flows through injection crossover pipe 260 and into annulus gas conduit 242 downstream of valve 244. Valve 244 is closed, and steam flows through emulsion conduit to well head 106 and into the production well.

Injection of steam into the production well forces circulation of steam in the reservoir and ultimately forces steam back up the well bore, to be produced through well head 106. Produced steam is received in emulsion conduit 234 and flows through emulsion conduit 234 to tie pipe 264. The produced steam then flows through tie pipe 264 into annulus gas conduit 242. Annulus gas conduit 242 also receives produced steam from injection assembly 204 through trunk crossover 276 and production crossover pipe 262. The produced steam flows through annulus gas conduit 242 to trunk line 117 and then to startup skid 300.

Referring to FIG. 15, an injection assembly 204 is depicted during installation to wellhead 104. Injection assembly 204 is transported to the site of reservoir 100 as an assembled unit, for example, in a shipping container. Injection assembly 204 is then removed from the shipping container and positioned proximate well bead 104. Prior to such movement of injection assembly 204, a plurality of wheels 280 may be installed to frame 208, to permit rolling movement of injection assembly 204, as depicted by the arrow in FIG 15. The wheels 280 may be temporarily attached to frame 208 tor initial installation or during well servicing over the life of the well. Wheels 280 may, for example, be bolted to frame 208. In the event a well requires servicing, the piping assembly will be decoupled from the wellhead and piping of trunk 107. After piping is unbolted, the bolts on the pile connectors will be removed and the piping assembly will be jacked up to attach wheels 280 (e.g. by bolting). After wheels 280 are attached, the piping assembly may be lowered with jacks and the weight of the module will rest on wheels. The module may then be rolled away from the wellhead for the well servicing to commence. The frame 208 may, for example, be pulled with a service truck via a simple hitch device.

Frame 208 may have a removable section 282 which may be removed to allow injection assembly 204 to be rolled into position at well head 204. Specifically, removable section 282 may be detached, creating an opening in frame 208 through which wellhead 104 can be received between opposing structural members 218. Removable section 282 may be removably attached to adjacent structural members by a set of bolted flanges, or by other suitable means.

In other embodiments, frame 208 may be raised and then lowered into position around well head 104, with structural members 218 on opposing sides thereof.

Once injection assembly 204 is in position, steam conduits 210-1, 210-2 are attached to well head 104 at one end and to steam trunk line 112 at another end. Blanket gas conduit 232 is attached to well head 104 at one end and blanket gas trunk line 116 at another end. Installation of production assembly 206 is substantially identical to that of injection assembly 204.

FIG. 16 depicts a method 1000 of completing a hydrocarbon well. At block 1002, frame 208 containing an injection assembly 204 is moved into position at an injection well head 104. Frame 208 containing a production assembly 206 is moved into position at a production well head 106. In some examples, the frames may be rolled into place, and a removable frame section may be removed so that the respective well head can be received between structural members 218 of the frame 208.

At block 1004, with frame 208 in position, fluid conduits of injection assembly 204 and production assembly 206 are connected to well heads 104, 106, respectively. That is, steam conduits 210-1, 210-2 are connected to first and second ports of well head 104 and blanket gas conduit 232 is connected to a third port of well head 104. Emulsion conduit 234 is connected to a first port of well head 106 and annulus gas conduit 242 is connected to a second port of well head 106.

At block 1006, fluid conduits of injection assembly 204 end production assembly 206 are connected to trunk lines. That is, steam conduits 210-1, 210-2 are connected to steam supply trunk line 112 and blanket gas conduit 232 is connected to blanket gas trunk line 116. Emission conduit 234 is connected emulsion trunk line 114 and annulus gas conduit 242 is connected to annulus gas trunk line 117.

In some embodiments, method 1000 may proceed from block 1000 directly to block 1008, at which steam injection is commenced in the injection well, and a mechanical lift device is activated in the production well to commence hydrocarbon production.

In some embodiments, method 1000 may include startup process 1010, 1012, 1014. In such embodiments, once the injection assembly 204 and production assembly 206 are in place and fluid conduits connected to the well heads and trunk lines, at block 1010, crossover piping may be installed. Specifically, selection crossover pipe 252 may be installed at injection assembly 204 and injection crossover pipe 260 may be installed at production assembly 206. First, trunk crossover 274 may be installed between crossover pipe 252 and 260, connecting them in fluid communication.

Production crossover pipe 254 may be installed at injection assembly 204. Production crossover pipe 262 may be installed at production assembly 206. Production crossover pipe 262 of injection assembly 204 may provide pressurized steam from injection assembly 204 to production assembly 206 by way of crossover pipes 254, 262 by way of second trunk crossover 276. Tie pipe 264 may be installed between emulsion conduit 234 and annulus gas conduit 242, permitting flow of steam from emulsion conduit to annulus gas conduit.

At block 1012, valve 220-1 of short-string steam conduit 210-2 and valve 244 of annulus gas conduit 242 are closed and steam may be injected down each of the injection well and the production well, and circulated back up the respective wells. Such circulation of steam, which may be referred to as a startup mode, may continue for a period typically lasting between 30 and 90 days.

Thereafter, at block 1014, crossover piping may be removed from each of the assemblies and the connection ports sealed. Valves 220, 244 are opened, and the process moves to block 1008, at which normal operation is commenced for producing hydrocarbons from reservoir 100 using a mechanical lift device.

In some examples, completion method 1000 may include startup blocks 1010, 1012, 1014 on initial startup of a reservoir or any other time when it is desired to increase the reservoir temperature. Startup blocks 1010, 1012, 1014 may be omitted, for example, if production is being re-started after a temporary shut-down.

As described above and depicted in FIGS. 1-16, well heads 104, 106 are oriented vertically. In other embodiments, well heads 104, 106 may be angled correspondingly to a slanted well bore. For example, FIGS. 17-18 depict an angled injection well head 104′ and an angled production well head 106′. Injection assemblies and production assemblies may be modified to accommodate such well heads. For example, FIG. 17 depicts an injection assembly 204′, substantially similar to injection assembly 204 except with a shortened frame 208′. Rather than receiving well head 104′ between structural members 218, injection assembly 204′ is configured so that frame 208′ is positioned adjacent well head 104′. Steam conduits 210-1′, 210-2′ extend from frame 208′ to connect to well head 104′. FIG. 18 depicts an example production assembly 206′ configured to connect to slanted production well 106′. Frame 208′ of production assembly 206′ is shortened relative to that of production assembly 206, and is positioned adjacent well head 106′. Emulsion conduit 234′ and annulus gas conduit 242′ extend from frame 208′ to connect to well head 106′.

As described above, steam is injected into the injection well bore through steam conduits 210-1, 210-2. However, in some embodiments, suitable solvents may be injected in addition to or instead of steam. Suitable solvents will be apparent to skilled persons.

Conveniently, injection and production assemblies disclosed herein are relatively compact and may, for example, be loaded in intermodal transport containers. Conversely, many existing techniques for connecting wells to well pad trunk lines require large, heavy structures and piping, which may be difficult to ship. Indeed, existing devices may be sufficiently large that transport over more than very short distances, or by modes other than overland transport may be impractical or prohibitively expensive. In such cases, equipment may need to be fabricated and assembled near the reservoir. Unfortunately, many reservoirs are located in regions where the cost of manufacturing is high. For example, infrastructure and labour may be scarce and expensive in remote regions.

Ease of shipping may therefore allow for substantial improvements in cost-efficiency. Piping assemblies as disclosed herein may, for example, be manufactured remotely (e.g. overseas) from reservoirs, allowing consolidation of production in desirable locations and accompanying cost reductions.

Moreover, piping assemblies disclosed herein may be suitable for many different onshore applications and components may therefore be standardized. For example, piping assembles disclosed herein may be appropriate for use with vertical and horizontal wells, slant wells, and a variety of well pad layouts and spacing. For example, FIGS. 19A-19C depict possible pad layouts. In FIG. 19A injection wells and production wells are arranged in respective rows parallel to and on opposite sides of the pad trunk 107. injection assemblies 204 are positioned approximately 10 metres from one another in a direction parallel to the trunk 107. Likewise, injection assemblies 206 are positioned approximately 10 metres from one another in a direction parallel to the trunk 107 and approximately 30 metres from one another in a direction perpendicular to the trunk 107. In FIG 19B, injection wells and production wells are drilled on the same side of the trunk 107. Injection assemblies 204 are positioned in a row parallel to the trunk 107, approximately 10 metres from one another. Production assemblies 206 are positioned in a row parallel to the trunk 107, approximately 10 metres from one another. Production assemblies 206 are offset from injection assemblies 204 by approximately 5 metres in a direction parallel to trunk 107 and approximately 5 metres in a direction perpendicular to trunk 107. In FIG. 19C, injection and production wells are arranged in pairs, with the pairs in a row parallel to trunk 107. The injection assembly 204 and production assembly 206 of a pair are spaced approximately 15 metres from one another in a direction parallel to trunk 107. Pairs are spaced approximately 15 metres from one another in a direction parallel to trunk 107. The arrangements of FIGS. 19A-19B may be typical of vertical wells, while the arrangement of FIG. 19C may be typical of slant wells.

Injection assemblies 204 and production assemblies 206 may be used in the depicted arrangements, or numerous other arrangements. Accordingly, they may be used as standard well head modules, which may allow for efficiency in designing and layout out well pads.

The design of piping assemblies disclosed herein may provide for relatively simple installation and servicing. While many existing approaches use custom in-field fitting, injection and production assemblies disclosed herein may be standardized, and relatively easy to install, remove and service by movement as a unit.

The detailed embodiments described herein are examples only and are not limiting. Rather, modifications are possible, as will be apparent to skilled persons in view of the specification as a whole. 

What is claimed is:
 1. A piping assembly for a well head of a steam-stimulated hydrocarbon well, comprising: a first fluid conduit for connecting a first fluid port of said well head to a first pipeline; a second fluid conduit for connecting a second fluid port of said well head to a second pipeline; said first fluid conduit and said second fluid conduit mounted to a frame for transportation of said fluid conduits and said frame as a unit.
 2. The piping assembly of claim 1, further comprising a plurality of wheels mounted to said frame.
 3. The piping assembly of claim 1, wherein said first fluid conduit comprises an expansion loop.
 4. The piping assembly of claim 1, wherein said first fluid conduit comprises first and second segments pivotably joined to one another.
 5. The piping assembly of claim 4, wherein said first fluid conduit comprises a plurality of swivel joints pivotably connecting segments of said first fluid conduit to one another, at least one of said swivel joints permitting pivoting about multiple axes.
 6. The piping assembly of claim 4, wherein said plurality of swivel joints is configured to allow for vertical movement of an end of said fluid conduit connected to said first fluid port.
 7. The piping assembly of claim 1, wherein said first conduit comprises one of: a pressure control valve; and a flow control valve and said piping assembly further comprises a controller operable to operate said control valve in response to a measurement of one of: pressure; and flow rate at a pumping device in said well.
 8. The piping assembly of claim 7, wherein said frame has a section that is removable to create an opening for receiving said well head between opposed structural members as said assembly is moved into position at said well head.
 9. The piping assembly of claim 1, wherein said first fluid conduit comprises a crossover port for connection to another piping assembly of another well in a reservoir start-up mode.
 10. The piping assembly of claim 9, wherein said second conduit comprises a crossover port for connection to another piping assembly of another well in a reservoir start-up mode.
 11. The piping assembly of claim 9, wherein said well head is one of a steam injection well head and a hydrocarbon production well head, and said another piping assembly is connected to the other of a steam injection well head and a hydrocarbon production well head.
 12. The piping assembly of claim 1, wherein said well head is an injection well head and said first fluid conduit is a steam line for injecting steam through said well head into a well bore.
 13. The piping assembly of claim 12, comprising a third fluid conduit for injecting steam through a third fluid port of said well head into said well bore at a different location along said well bore than said first fluid conduit.
 14. The piping assembly of claim 12, wherein said second conduit injects a heated gas through said well head into said well bore.
 15. The piping assembly of claim 1, wherein said well head is a production well head, and said first fluid conduit is for receiving produced hydrocarbons through said well head.
 16. The piping assembly of claim 14, wherein said second fluid conduit is for fluid communication of annulus gas with a pumping device in said well bore.
 17. The piping assembly of claim 1, wherein each of said fluid conduits comprises a releasable coupling device for connection to said well head and a releasable coupling device for connection to a pipe line.
 18. The piping assembly of claim 1, wherein said assembly defines a spatial envelope circumscribing the assembly no larger than 39 feet, 4 inches in length, 7 feet, 6 inches in width and 7 feet, 5 inches in height.
 19. The piping assembly of claim 1, wherein said assembly defines a spatial envelope circumscribing the assembly no greater than 19 feet, 8 inches in length, 7 feet, 6 inches in width and 7 feet, 5 inches in height.
 20. A method of completing a steam-stimulated hydrocarbon well, comprising: moving a structural frame to a well head of said well, said frame carrying first and second fluid conduits for connecting said well head to first and second pipelines, respectively; attaching said first fluid conduit to a first port of said well head and attaching said second fluid conduit to a second port of said well head; connecting said first fluid conduit with said first pipeline, thereby establishing fluid communication between said first port and said first pipeline; and connecting said second fluid conduit with said second pipeline, thereby establishing fluid communication between said second port and said second pipeline. 